Note: Descriptions are shown in the official language in which they were submitted.
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UNDER-BALANCED DRILLING SEPARATION APPARATUS AND METHODS
Technical Field
The present invention relates to improvements in under-balanced methods
of subterranean well drilling and apparatus used therein.
Background
In under-balanced drilling, as opposed to conventional drilling, down-hole
well pressure at the formation is maintained below the formation pressure by
the
utilization of a relatively light base drilling fluid. The under-balanced
condition
avoids contamination of the formation by reducing the chances that the
drilling
fluids and the "cuttings," suspended solids produced by the action of the
drill bit,
will be forced into the permeable reservoir formation. Several types of base
drilling fluid may be used in under-balanced drilling. Water-based and oil-
based
drilling muds may be used, however, water and lighter oil-based fluids, such
as
diesel fuel and crude oil, are more commonly used. In some situations the base
drilling fluid will have a specific gravity too high to successfully use in an
under-
balanced well. In such situations, the controlled mixture of additives, such
as
nitrogen gas, to the base drilling fluid produces an operating fluid of a
specific
gravity selected to maintain an under-balanced well.
The higher formation pressures usually result in well formation fluids, such
as hydrocarbon oil, hydrocarbon gas and well water, flowing into the well and
mixing with the operating fluid and cuttings. The returning drilling stream
reaches
the surface wellhead as a mixture of formation oil, formation gas, well water,
solid
cuttings and operating fluid. If the operating fluid is oil-based, any liquid
hydrocarbons produced from the well will mix with the operating fluid.
Similarly, if
the operating fluid is water-based, any well water produced will mix with the
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water-based operating fluid. If additive gasses were mixed in forming the
operating fluid, the additive gases will mix with any hydrocarbon gas produced
in
the well.
In under-balanced drilling the returning drilling stream is at elevated
pressures and when separation of the stream elements is desired, separation
must be performed in a closed container or tank. Unfortunately, liquid-gas
separation is less efficient when performed at elevated pressure levels. It is
important to remove as much hydrocarbon gas from the base drilling fluids as
possible. Basic hydrocarbon equilibrium phase behavior dictates that lowering
the separation pressure reduces the hydrocarbon gas remaining in solution as a
liquid. However, reducing the separation pressure, to release the gas from the
liquid, increases the actual gas volume, thereby complicating gas handling and
flow issues. In conventional, balanced drilling the operating fluid is not
impregnated with large quantities of well formation fluids and, consequently,
the
operating fluid does not need to be separated from the returning stream at the
surface at elevated pressures.
In a closed, balanced drilling system, controlling the specific gravity of the
operating fluid flowing into the well is relatively uncomplicated, making
maintenance of the stability of the well relatively simple. In under-balanced
drilling the fluid mixture circulating in the well is not a closed system
because of
the addition of formation fluids down-hole. The influx of these formation
fluids and
gases greatly complicates the problem of under-balance pressure control
through
operating fluid specific gravity management.
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Separation of the well formation fluids from the base drilling fluids is
necessary before the base drilling fluids may be returned to the well and is
accomplished by processing the returning stream through a separation system.
The separation system should have the capacity to remove approximately the
same or in excess of the volume of gas from the returning stream as is being
added to the operating fluids down-hole. That is, the separation system should
keep up with production of formation gas from the well to maintain the
stability of
the well during drilling operations.
Complicating matters, the separation system must handle typical wellhead
pressures of the returning stream, which during under-balanced drilling can
range
from 25 psi to 3000 psi. Wellhead pressures are typically maintained as low as
possible but still high enough to handle the returning stream volume. Reducing
the pressure of the returning stream from the wellhead operating pressure by
venting into a closed chamber can cause foaming, which reduces the efficiency
of
the liquid-gas separation process.
During drilling a large volume of heavy cuttings is produced and returned to
the surface wellhead in the returning stream. In conventional drilling the
returning
stream is treated with shale shakers and mud pits. In under-balanced drilling
it is
necessary to remove the cuttings, or solids produced during drilling, from the
returning stream mixture in the pressurized tanks to prevent clogging of the
tanks.
For safety reasons, in under-balanced drilling, it is first necessary to
remove the
gases from the returning stream. Removal of the solids from the pressurized
chambers without shutting down the drilling operation presents difficulties.
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Summary Of The Invention
The present inventions contemplate improved methods and apparatus for
separating and control of drilling fluids in under-balanced drilling. The
present
inventions separate the base drilling fluids from the solids, additives and
well gas
and liquids; continuously measures the separated gases and liquids and
calculates the amount of additives needed to attain the desired operating
fluid
specific gravity to maintain control of the under-balanced drilling. The
present
inventions also perform liquid-gas separation at a reduced returning drilling
fluid
pressure. As an added advantage, the methods and apparatus of the present
inventions can be used with (upstream of) conventional atmospheric pressure
shale shakers, mud pits and the like. In addition, the present invention uses
a
multi-stage (two or more) controlled pressure drop during separation. The
smaller
controlled pressure drops help prevent foaming and thus separation efficiency
is
increased.
Brief Description Of The Drawings
The accompanying drawings are incorporated into and form a part of the
specification to illustrate several examples of the present inventions. These
drawings together with the description serve to explain the principles of the
inventions. The drawings are only for purpose of illustrating preferred and
alternative examples of how the inventions can be made and used and are not to
be construed as limiting the inventions to only the illustrated and described
examples. The various advantages and features of the present inventions will
be
apparent from a consideration of the drawings in which:
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FIGURE 1 is a schematic view of an improved apparatus for practicing the
improved method for separation and control of drilling fluids during under-
balanced drilling of the present invention;
FIGURE 2 is a flow diagram of an improved method of the present
invention for controlling the drilling fluid during under-balanced drilling;
FIGURE 3 is a section view of an embodiment of a separator of the
present invention for use in separating drilling fluids in an under-balanced
drilling
operation;
FIGURE 4 is an alternate embodiment of an inlet for the separator of
FIGURE 3;
FIGURE 5 is an alternate embodiment of an inlet for the separator of
FIGURE 3;
FIGURE 6Ais a top view of an alternate embodiment of an inlet for the
separator of FIGURE 3; and
FIGURE 6B is a side view of the alternate embodiment of the inlet of
FIGURE 6A.
Detailed Description
The present inventions will be described by referring to the drawings of
apparatus and methods showing various examples of how the inventions can be
made and used. In these drawings, reference characters are used throughout the
several views to indicate like or corresponding parts.
In Figure 1, one embodiment of a drilling fluid separation and control
system 10 for use in under-balanced drilling is shown. A selected operating
fluid
is used in an under-balanced well formation 26 as shown. The base drilling
fluid
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20 is relatively light and may consist of water-based mud or oil-based mud,
but is
more likely to be a water-based fluid or a lighter oil-based fluid, such as
diesel
fuel, crude oil or the like. The specific gravity of the base drilling fluid
20 can be
altered by mixing an additive 22, typically a control gas, into the drilling
base fluid
20 in a mixer 24, such as is known in the art, to create an operating fluid 18
for
introduction into the well. The additive 22 may be nitrogen, carbon dioxide, a
hydrocarbon gas or other gases as is known in the art. Various pumps, tubing,
valving and control devices, such as pump 16, may be used as is known in the
art. The specific gravity of the operating fluid 18 is manipulated to maintain
the
down-hole well bore pressure DP at less than the reservoir pressure RP present
in the formation 26.
The operating fluid 18 is circulated down-hole where well formation
materials, such as hydrocarbon oil 28, hydrocarbon gas 30, and well water 36
flow into the well and mix with the operating fluid 18 to create a returning
drilling
stream 40. Depending on the formation, oil, gas and water may be produced
independently or simultaneously. One of the purposes of the returning stream
40
is to carry cutting solids 32 back to the surface wellhead 34. The mixture
returning from down-hole, the returning drilling stream 40, therefore may
include
formation oil 28, formation gas 30, base drilling fluid 20, cutting solids 32,
additive
gas 22, and formation water 36 depending on the formation fluids produced by
the well.
If the base drilling fluid 20 is oil based, the formation oil 28 will mix with
and
dilute the base oil used to initiate drilling. Similarly, if the base drilling
fluid 20 is
water based, the well water will mix with and dilute the water used originally
to
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begin operations. This mixing is typically considered acceptable or desirable
as
the well water or native crude becomes the base drilling fluid. Lastly, the
additive
gases will mix with any hydrocarbon gas produced from the well.
The returning stream 40, once at the surface, is under a wellhead pressure
WP which can typically range from 25 psi to 3000 psi. When separation of the
stream elements is desired, separation must be performed in a closed container
or tank. Unfortunately, liquid-gas separation is less efficient when performed
at
elevated levels. Basic hydrocarbon equilibrium phase behavior dictates that
lowering the separation pressure reduces the hydrocarbon gas remaining in
solution as a liquid. However, reducing the separation pressure, to release
the
gas from the liquid, increases the actual gas volume, thereby complicating gas
handling and flow issues. The pressurized system presented allows the
flexibility
of varying the separation pressure to balance the opposing goals of releasing
*as
much gas as possible from the returning stream 40 and avoiding releasing more
gas than the system has the capacity to handle.
The returning stream 40 is directed into a first stage separation process 50
to undergo a first stage of separation at a first pressure P1. The pressure P1
in
the first stage separation process 50 may vary greatly but is typically around
25
psi. The reduction in pressure, if desired, from the wellhead pressure WP to
the
first stage pressure P1 allows for the more efficient separation of formation
gas 30
from the returning stream 40. Appropriate pressure reduction and control
equipment, as is known in the art, may be employed in transfer of the
returning
stream 40 to the first stage 50.
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In the first stage 50, formation gas 30 and additive gas 22 is removed as
high-pressure gas 46 by gas removal means 52. The first stage 50 may include
utilization of a pressure vessel such as a three-phase vertical pressure tank.
One of the benefits of the first stage 50 is the catching and handling of the
vast majority of the solids as soon as possible. A solids slurry 48, including
the
cuttings 32, is collected and removed from the returning stream 40 by solids
removal means 54. The solids slurry 48 may then be processed with
conventional treatment equipment as desired, including shale shakers,
desilters
and desanders. If an oil-based drilling fluid is employed, the solids slurry
48 will
comprise oil-based fluids and solids. If a water-based drilling fluid is used,
the
slurry will include water and solids. The conventional treatment systems are
capable of separating the base drilling fluid, whether oil or water based,
from the
solids so that the salvageable base drilling fluid may be returned to the well
for
further operations.
The remaining fluids, the treated returning fluids 60, which may include
water 36, drilling base fluid 20, any formation gas 30 still remaining in the
pressurized treated fluid 60, and formation oil 28, exit the first stage 50 by
a fluid
removal means 58.
The treated returning fluid 60 now enters a second stage separation
process 70 to undergo a second stage of separation at a second pressure P2.
Typically pressure P2 will be lower than pressure P1 to enhance further gas
separation from the liquid treated return fluid 60. The pressure P2 may vary
greatly, can be atmospheric pressure, and is typically around 5 to 10 psi. The
second stage 50 may also include use of a three-phase vertical pressure tank.
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Production gas 30 and remaining additive gas 22 are removed more completely
during this stage.
The major benefit of a multi-stage separation allows for more convenient
and efficient handling of the smaller volume of gas released at the high
pressure
P1 combined with the more complete release of gas at the lower pressure P2. At
the higher-pressure first stage 50, gas is released in a relatively lesser
volume
than at the lower pressure stage 70. At the lower pressure stage 70, more gas
is
released from the liquid resulting in more complete gas-liquid separation.
Another advantage of a multi-stage separation method is the reduction or
elimination of foaming which can occur when a returning stream bearing
formation
gas undergoes a drastic drop in pressure. A two-stage separation process
allows
selection of pressures P1 and P2 to provide a gradual step-down in pressure
selected to allow removal of formation gas from the returning stream at each
pressure level without foaming. When higher pressures or greater gas volumes
are encountered, more than two stages of pressure may be utilized.
Low-pressure gas 72 is removed from the treated returning fluid 60 by gas
removal means 74. The low-pressure gas stream may be joined with the high-
pressure gas 46 from the first stage 50, as shown in Figure 1, by methods
known
in the art.
Where the well is producing hydrocarbons and water, or where the
selected base drilling fluid is water, the water, a heavy liquid, is collected
and
removed by a heavy liquid removal means 76. The water may then be further
treated as desired, such as for the removal of fine sediments, using
conventional
separation equipment and techniques 80, such as with desilters, vacuum
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degassers, mud pits and pumps. The hydrocarbon formation oil 28 is removed in
the second stage 70 by an oil removal means 78. If the oil is to be used as
the
base drilling fluid, it may be treated using conventional treatment methods
and
returned to use in the well. Where the well is producing only hydrocarbons,
with
virtually no water production, and the base fluid is oil based, it may not be
necessary to remove two streams of fluid from the second stage 70 as shown in
Figure 1. Instead, a single stream of oil-based drilling fluid may be removed
via a
single outlet means.
This two stage method separates the returning stream into components: a
solids slurry, which may include oil or water; high and low pressure gas,
which
may include hydrocarbon and additive gas; liquid hydrocarbons, and water. The
liquid hydrocarbons or water may serve as the base drilling fluid and be
circulated
to the well after appropriate treatment. The two stage method presents
advantages over a single stage method utilizing a four-phase separator which
are
prone to filling with solids and require much larger tanks. The efficiency of
such
four-phase separators is compromised by having the additional complexity and
dedicated volumes necessary for all four phases.
The high and low-pressure gases 46 and 72 are measured by gas testing
means 84 to determine at least the flow rate of formation gas 30 produced from
the well. Other data, such as the pressure and temperature of the gas stream,
the composition of the gas, or the produced gas percentage and specific
gravity,
may also be measured. It is understood that the high and low-pressure gases 46
and 72 may be measured separately or that the gases may be combined through
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appropriate methods and measured into a single stream of gas. The gas may
then be stored, flared, directed to a pipeline or otherwise handled.
Similarly, the formation hydrocarbon oil 28 is measured by oil testing
means 94 to determine at least the flow rate produced from the formation.
Other
data such as the specific gravity, volume or percent volume of the liquid, and
the
pressure and temperature of the liquid stream, may be measured as desired. The
oil is then directed to conventional storage tanks or otherwise handled as
explained above.
The solids slurry, and the liquids recovered from the slurry, may also be
measured by testing means 96 for flow rate, pressure, temperature, solid types
and percentages of each type. Lastly, any existing heavy liquids retrieved
from
the second stage 70 may be tested by testing means 98 for flow rate and other
data.
The recovered drilling base fluid 20, which may be heavy water based
fluids or light oil based fluids, is circulated back into the well as shown.
The
drilling base fluid 20 is passed through the mixer 24 where a volume of
additive
22 may augment the fluid as needed to achieve a selected operating fluid
specific
gravity. The volume of additive 22 needed to achieve the required specific
gravity
is determined, at least in part, from the measured volume of formation gas and
formation oil which was produced from the formation and separated using the
described two-stage method. That is, after determining the flow rates,
temperatures, pressures and other data, of formation hydrocarbons and water
which became mixed with the operating fluid, the measured data can be used in
conjunction to calculate the specific gravity needed for the operating fluid
to
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maintain well stability in the under-balanced condition. Thereafter, the
required
amount of additive may be determined and mixed into the base drilling fluid.
The
system 10 offers a continuous separation of components, continuous
measurements of those components, and continuous calculations of needed
additives to be mixed into the base drilling fluid.
The fluid separation and control system 10 is shown in simplified form and
it is understood that the system may include further control devices such as
tubing, valves, pumps, compressors, electrical control and signal devices and
the
like at any step of the process. It is further understood that the separation
system
may include three or more stages with a pressure step-down at each stage to
further enhance gas removal and to help prevent foaming. The embodiment
above may utilize two three-phase separator vessels or combinations of other
known separator units to extract the gas, oil, drilling base fluids, water and
cuttings, and further, that the order of the separation is not limited by the
one
preferred embodiment described above. Further, at any or each stage, further
separation steps may be taken, such as the separation of heavy and light
liquids
during the first stage from the returning stream.
Figure 2 shows a separation and control method for under-balanced
drilling. A returning stream is removed from the well in step A. The returning
stream may include base drilling fluid, additives, cuttings, formation gas,
formation
oil and water. Since the well is being drilled in an under-balanced condition,
oil
and gas from the subterranean well formation will mix with the operating fluid
during operations. The returning stream will reach the surface wellhead under
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pressure. The returning stream may be removed from the well using pumps,
valving and other equipment and methods known in the art.
In step B, formation oil and gas, water, additives and solids are separated
from the returning fluid. The appearance of each of these components depends
on the well production and selected additives and base drilling fluid. This
step
may be accomplished by the two-stage process explained herein. Further
methods of conventional separation may be used as well, such as shale shakers,
desilters, vacuum degassers, mud pits, atmospheric vessels and the like.
In step C, all returning materials are measured to determine their
quantities. Other measurements and data may be extracted as well. Based at
least in part on those quantitative measurements, in step D, quantities of
additives
for the base drilling fluid are determined. The measurement of the quantities
of
hydrocarbon materials produced from the well formation can be used to
determine the required fluid specific gravity necessary to maintain and
control
under-balanced drilling. Other measurements, such as down-hole pressure and
temperature, wellhead pressure and temperature, the pressures and
temperatures of the separated components, the specific gravities and
percentage
compositions of each of the components, and the like may also be used to help
determine the quantities of additives to be added to the drilling fluid and
the rates
of injection of the additive. In step E, the determined quantities of
additives are
added to the base drilling fluid to achieve a selected operating fluid
density. And
in step F, the operating fluid is returned to the well.
Figure 3 shows in detail one embodiment of a three-phase separator 100
for processing the returning stream 40 from an under-balanced drilling
operation
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that may be used in the first stage separation process 50. The separator 100
comprises a vertical pressure vessel having an interior chamber 102 which is
divided into a solids slurry section 104, a liquids section 106, and a gases
section
108. The vessel 100 receives returning stream 40 through inlet 110. The
returning stream 40 may, depending on the condition of the well formation and
selected base drilling fluid, include formation oil, formation gas, water,
base
drilling fluids and cuttings, and is returned under pressure. The pressure P1
in
the vessel chamber 102 may be selected over a wide range but is preferably
around 25 psi to induce gas separation.
The inlet 110 may comprise a hydrocyclone assembly 112 as shown in
Figure 4. Hydrocyclone inlet diverter assemblies are known in the art and
widely
used as desanders and desilters, and may be purchased from various supply
companies. The hydrocyclone assembly 112 is used in a unique fashion in the
vessel as shown. The assembly 112, mounted to receive the returning fluid
through an opening, acts as an inlet diverter. The assembly 112 is shown
mounted in the interior chamber 102, but may alternately be placed exterior to
the
pressure vessel 100, as is known in the art. The hydrocyclone assembly diverts
the incoming returning stream 40 into a vortex in which centrifugal forces
separate the gases 30, which exit through a top opening 114 of the assembly
112, from the solids and liquids which exit through a bottom opening 116 of
the
assembly 112. A vortex breaker 120, such as is known on the art, is designed
to
reduce or eliminate the vortex formed by the hydrocyclone and prevent the
gases
from reaching the liquids section 106. The hydrocyclone extends between the
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gases section 108 and the liquids section 106 of the interior chamber 102 so
that
the gases and solid-liquid mixtures are separated upon exiting the inlet 110.
The hydrocyclone assembly may be replaced with a tangential vessel
assembly 90 shown in Figure 4, a tangential diverter assembly 92 shown in
Figure 5, or a vortex tube cluster assembly 94 shown in Figures 6A and B. Each
of these assemblies are known in the art; the vortex tube cluster being
available
from Porta-test, for example. For pressure drop reasons, multiple parallel
inlet
diverters may be used.
The gases 30 are contained in the gases section 108 of the interior
chamber 102. An optional mist extractor 124, such as known in the art and
available commercially from Burgess Manning, Peerless and other suppliers, may
be employed to further separate any fine liquid droplets from the gases. A top
chamber opening 126 provides an exit for the gases 30. Appropriate control and
pressure valves 130 may be employed to control the exit of the gases from the
chamber 102. Additionally, a relief valve system 128 may be provided as shown.
Solids handling and removal is of high importance. The bottom head 140
is preferably cone shaped for an enhancement in solids separation over more
common ellipsoidal, flanged and dished, or spherical heads. A solids slurry
48,
formed of the solids and either heavy liquids or light liquids of the
returning stream
40, depending on the constituents of the returning stream, collects at the
solids
slurry section 104 at the bottom of the chamber 102 due to gravity. The solids
slurry 48 is agitated or fluidized to enhance movement of the solids 142
towards
and through a solids exit 144 in the bottom of the vessel 100. The slurry 48
movement is enhanced by a sparging line, a sparging ring, a vortex generator,
an
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eductor, dynamic mixer sand pan or other agitating means or a combination
thereof.
Shown in Figure 3 are dual sparging rings 148 which act to fluidize and
agitate the solids as they move through the bottom of the chamber 102. The
appropriate valving 162 and flush fluid supply 164 is provided. Vortex
generators
are available commercially from Merpro, among others.
Appropriate valving 150 and, if desired, a slurry pump 152 are provided to
handle the solids as they exit the vessel 100. The solids slurry 48 may then
be
moved to a conventional handling system if desired. The solids may be
measured and quantified upon leaving the vessel.
The liquids section 106 of the chamber 102 contains the returning fluids,
which separate by gravity from the solids 32 and gases 30. The returning
fluids
may include the water, formation oil 28 and drilling base fluid 20 of the
returning
stream 40, and may also include any gases which remain in the liquid. In the
preferred embodiment a liquid outlet 156 is contained in the side wall 158 of
the
chamber 102. Appropriate valving 158, pumps 160 and the like, known in the
art,
remove the treated liquid 60 from the chamber 102. Level control devices, such
as level control device 162, may be employed as needed. Alternately, the
chamber 102 may be provided with multiple liquid outlets vertically spaced to
remove light hydrocarbon liquids and heavy drilling fluids, as is known in the
art.
The treated liquids, upon leaving the vessel, are preferably removed to a
second stage separation process. The second stage may include a second
three-phase vertical pressure vessel of similar construction which operates at
a
lower pressure. The second stage vessel may separate the remaining liquid into
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gas, light liquids and heavy liquids, as desired, and may operate at a
pressure
different than that of the vessel 100.
The embodiments shown and described above are only exemplary. Many
details are often found in the art such as: "Surface Production Operations,"
Arnold and Stewart. Therefore many such details are neither shown nor
described. It is not claimed that all of the details, parts, steps or elements
described and shown were invented herein. Even though numerous
characteristics and advantages of the present inventions have been set forth
in
the foregoing description, together with details of the structure and
functions of
the inventions, the disclosure is illustrative only, and changes may be made
in
detail, especially in matters of shape, size and arrangement of the parts
within the
principles of the inventions to the full extent indicated by the broad general
meaning of the terms used in the attached claims.
The restrictive description and drawings of the specific examples above do
not point out what an infringement of this patent would be, but are to provide
at
least one explanation of how to make and use the inventions. The limits of the
inventions and the bounds of the patent protection are measured by and defined
in the following claims.
What is claimed is:
